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Alliant Energy’s (LNT) CEO Pat Kampling on Q3 2015 Results – Earnings Call Transcript

Alliant Energy Corporation (NYSE: LNT ) Q3 2015 Earnings Conference Call November 06, 2015 10:00 AM ET Executives Susan Gille – Manager, IR Pat Kampling – Chairman, President & CEO Tom Hanson – SVP & CFO Robert Durian – Vice President, Chief Accounting Officer and Controller Analysts Andrew Weisel – Macquarie Capital Brian Russo – Ladenburg Development Operator Thank you for holding, ladies and gentlemen, and welcome to Alliant Energy’s Third Quarter 2015 Earnings Conference Call. At this time, all lines are in a listen-only mode. And today’s conference is being recorded. I would now like to turn the conference over to your host, Susan Gille, Manager of Investor Relations at Alliant Energy. Susan Gille Good morning. I would like to thank you of — on the call and the webcast for joining us today. We appreciate your participation. With me here today are Pat Kampling, Chairman, President and Chief Executive Officer; Tom Hanson, Senior Vice President and CFO; and Robert Durian, Vice President, Chief Accounting Officer and Controller; as well as other members of the senior management team. Following prepared remarks by Pat and Tom, we will have time to take questions from the investment community. We issued a news release last night announcing Alliant Energy’s third quarter 2015 earnings narrowing 2015 earnings guidance. I’m providing 2015 through 2020 forward capital expenditure guidance. We also issued earnings guidance and the common stock dividend target for 2016. Press release, as well as supplemental slides that will be referenced during today’s call, are available on the Investor Page of our website at www.alliantenergy.com. Before we begin, I need to remind you the remarks we make on this call and our answers to your questions include forward-looking statements. These forward-looking statements are subject to risks that could cause actual results to be materially different. Those risks include, among others, matters discussed in Alliant Energy’s press release issued last night and in our filings with the Securities and Exchange Commission. We disclaim any obligation to update these forward-looking statements. In addition, this presentation contains non-GAAP financial measures. The reconciliation between non-GAAP and GAAP measures are provided in the supplemental slides, which are available on our website at www.alliantenergy.com. At this point, I’ll turn the call over to Pat. Pat Kampling Good morning and thank you for joining us today. The Veterans Day is just a few days away. I would like to take a moment and pay tribute to the approximately 400 proud veterans that work here at Alliant Energy and to those veterans are on the call with us today. We thank you for your service to our country and for protecting our freedoms. Enjoy your special day. Yesterday we issued press releases which included third quarter and year-to-date financial results our revised 2015 earnings guidance range. And for 2016, our earnings guidance and targeted common stock dividend. That release also provided updated detailed annual capital expenditure plans through 2019 and our capital expenditure total for 2020 to 2024. Tom will later provide details of the quarter, but I am pleased to report that we delivered another solid quarter. And since temperature was close to normal with the third quarter, at first we had no impact on our year-to-date earnings. So with the summer behind us, we are now in our 2015 earnings guidance but we are now including an adjustment to our ATC earnings to reflect the anticipated lower ROE. ATCs current authorized ROE is 12.2% we are reserving $0.03 per share for the year reflecting an anticipated ROE of 11.5%. Therefore we are changing the midpoint of this year’s earnings guidance range from $3.60 per share to $3.57 per share. Now looking at next year, the midpoint of our guidance for 2016 is $3.75 per share a 5% increase from our projected 2015 guidance as detailed on Slide number 2. This increase reflects a forecast with customer sales increase of 1% and earning on capital additions. Our long-term earnings growth objective continues to be 5% to 7% supported by our robust capital expenditure plan modest sales growth and constructive regulatory outcomes. The ability to earn our authorized returns on rate base additions of book utilities was incorporated in both retail electric base rate settlements. Those settlements have unique treatment that will allow you to reach earn on an increasing rate base while keeping customer base rates flat. The IPL settlement utilized the historic DAEC capacity payments that are included in base rates to more than offset rate-based growth and other changes in revenue requirements. This allows us to refund the difference to customers included $25 million refund in 2015 and a $10 million refund in 2016. The WPL settlement utilized previously recovered energy efficiency revenues it also increases in revenue requirements including the return on rate base additions. A balance of approximately $32 million will be amortized in 2016 and the amortization for this year is expected to be $80 million. To summarize, both creative retail rate case settlements allow us to earn on our increasing rate base or keeping retail electric base rates stable through 2016, which is last year of the settlement. Yesterday we also announced a 7% increase in a targeted 2016 common dividend level to $2.35 per share from our current annual dividend of $2.20 per share. By 2016, dividend target payout ratio is 62.5% which is consistent with our long-term targeted dividend payout ratio of 60% to 70% of consolidated earnings. We issued an updated capital expenditure plan for 2015 to 2019, totaling $5.8 billion, as shown on Slide 3. In addition, we have provided a walk from the previous 2015 to 2018 capital expenditure plan to our current plan shown on Slide number 4. As you can see the change in our forecasted 2015 to 2018 capital expenditure plan are driven primarily by additional investments on our electric and gas distribution systems and a $50 million reduction for the proposed Riverside Energy Center expansion in Wisconsin. The lower cost estimate of $680 million to $720 million excluding AFUDC and transmission was filed in supplemental test [indiscernible] with the PSCW yesterday. On Slide 5, we have provided a 10-year view of our forecasted capital expenditures. As you can see our planning additional new generation needs beyond 2019 which we anticipate will include gas, wind and other renewable resources. The additional renewables in our plan with economical for our customer energy needs as we continue to retire all the generating facilities. While reviewing Slide 5, it is also important to note that approximately 45% of the 10-year capital plan will be spent to enhance our electric and gas distribution systems to meet customers changing and growing needs. Investments in our gas distribution system are becoming more significant as evidenced by our recently completed $15 million [indiscernible] Wisconsin and we are supposed to cross $65 million [indiscernible] project in Iowa. Also for your convenience, we have already posted on our website the EEI Investor presentation that details the separated WPL and IPL updated capital expenditures through 2019 as well as updated rate-based estimates for 2014 through 2018. Now, let me brief you on our current construction activities. As year-end approaches, this has certainly been one of our busiest construction years. I must thank the employees and approximately 800 contract workers on our properties for working safely and for their assistance on these important projects. I’m extremely proud of the achievements we have made and continue to make and transitioning the environmental profile of our fossil generation fleet. We plan to reduce NOx emissions by approximately 80% and SO2 mercury emissions by approximately 90% by 2020 and we will continue to plan for a reduced carbon future. In Wisconsin, the installation of the scrubber and baghouse at Edgewater Unit 5 is approximately 75% complete and is expected to be in service in the second quarter of 2016. We are anticipating this project will come in approximately 10% below budget. We have recently a signed a contract with a joint-venture between Graycor industrial contractors and Sargent & Lundy to fund the engineering procurement and construction of the Columbia unit 2 SCR. The construction is scheduled to start in the second quarter of 2016 and WPL share the expenditure for this project of approximately $50 million. We do have an excellent track record of executing well on our these large construction projects, I am very pleased on power magazine name two of our power generating stations as our top plants for 2015. The recognition of IPLs [thermal] generating station and WPLs Columbia’s Energy Center which were excellent execution of this major investments and a dedication to a cleaner and more efficient operations. Construction of IPLs 650 megawatt combined cycle natural gas fired Marshalltown generating station is progressing well. The project is approximately 65% complete and is expected to be in service in the second quarter of 2017. KBR is the engineering, procurement, and construction contractor for this project which includes Siemens’ combustion turbine technology. In 2013, WPL announced that it would retire several older coal facilities and natural gas peakers. This retirements begin next month at Nelson Dewey and as well as in Unit 3. When WPLs prime retirements are completed the forecasted accredited capacity loss will be nearly 700 megawatts. As a consequence, WPL evaluated a wide range of alternatives to meet long-term energy and capacity needs for its customers. In 2014, WPL issued an RFP for market-based options. After evaluating all of our options, we concluded that Riverside Energy Center expansion with a new approximately 650 megawatt highly efficient natural gas generating facility was in the best long-term interest of our customers. This past April WPL applied for a certificate of public convenience and necessity or CPCN with the Public Service Commission of Wisconsin. The CPCN is progressing and in accordance with its procedure schedule on September 22 we filed that direct testimony and yesterday filed supplemental testimony through [indiscernible] updated cost projections. Intervener and Staff testimony will be filed by November 13, a public care will be conducted on November 17 in [indiscernible] and technical hearings are scheduled for December 21. We anticipate the commission issue decision on Riverside Expansion by May 2016. The proposed riverside expansion includes an approximate 2 megawatt solar installation on the property. Adjacent to riverside, on our Rock River landfill Hanwha Q Cells is currently constructing the largest solar plant at Wisconsin at 2.25 megawatts and we will purchase the power from them over the next 10 years. At our Madison general office installation of above 1000 solar panels from multiple manufacturers with 11 different types of solar modules is well underway. For this project we have partnered with the Electric Power Research Institute or EPRI to collect data and make it available to others. We also have several other solar projects under development from which we anticipate gaining valuable experience and how to best integrate solar in a cost-effective manner in our electro systems. Solar projects is in the developmental stage include owning and operating the solar panels at the Indian Creek Nature Center in Cedar Rapids Iowa and our recently issued RFP was placed in [indiscernible] solar project between 1 and 10 megawatts within our Iowa service territory. The projects resulting from the RFP will increase our system wise solar generation by 50%. Last month the EPA published its final rules through those carbon emissions from electric generating stations. We understand this is just one more step what will be a long process that includes legal challenges and the development of compliance plans. As we develop strategies, we will continue to take the approach of doing what’s best for our customers and the environment. We are fortunate that we operate in a state that has a long history of energy efficiency programs, environmental stewardship and support for renewable energy. There’s a some sort of excitement as you work to transform into the company our customers need as to be not only now, but well into the future. A major improvement to our customer experience is happening as we went live with our new customer care and billing systems for Wisconsin customers several weeks ago. And planned to go live with Iowa customers in early 2016. A $110 million investment replaces vintage mainframe systems from the 1980s. They will make communications with our customers more convenient and timely. We have already accomplished a great deal as a company as we transition to a cleaner more modern energy system. I want to thank a lot of employees for their creativity and finding cost-effective solutions in serving our customers well. Let me summarize the key message for today. We had a solid first three quarters of the year and are well positioned to deliver on this year financial and operating objectives. Our plan continues to provide for [audio gap] 5% to 7% earnings growth and 60 to 70% common dividend payout target. Our target 2016 dividend increased by 7% over the 2015 target dividend. Successful execution on our major construction projects includes completing projects on time and at a below budget in a safe manner. Work with our regulators consumer advocates, environmental groups and customers in a collaborative manner. We shape our organization to be lean and faster while keeping our focus on serving our customers and being good partners in the community. We will continue to manage the company to strike a balance between capital investment, operational and financial discipline, and cost impacted customers. Thank you for your interest in Alliant Energy and I will now turn the call over to Tom. Tom Hanson Good morning everyone. We have released third quarter earnings last evening with our non-GAAP earnings from continuing operations of a $1.63 per share and our GAAP earnings from continuing operations to a $1.59 per share. The non-GAAP to GAAP difference is due to a $0.04 per share charge resulting from approximately of 2% employees accepting voluntary separation packages as we continue focusing on effectively managing cost for our customers. 2015 third quarter non-GAAP earnings are $0.23 higher than the third quarter 2014 primarily due lower retail electric customer billing credits at IPL, higher electric sales and lower energy efficiency cost recovery amortization to WPL. Higher quarter-over-quarter EPS was partially offset by higher electric transmission service expense at WPL and the delusion impact of shares issued in 2015. Comparisons between third quarter of 2015 and 2014 earnings per share are detailed on slides 6, 7 and 8. For the first six months of this year we experienced virtually no temperature normalized retail sales growth. We are pleased that the third quarter brought an estimated $0.06 per share increase in earnings resulting from higher temperature normalized sales. Some of the growth experience in the third quarter of 2015 for residential and commercial is due to an earlier fall grain harvest in 2015 when compared to 2014. Of the retail sectors industrial continues to be the largest sales growth driver year-over-year. Quarter-over-quarter we have recognize in earnings increased of $0.05 per share from higher sales due to temperatures since the third quarter of 2014 had approximately 20% fewer cooling degree days compared to normal. However, the first three quarters 2015 temperatures were close to normal. Year to date non-GAAP earnings are tracking in line with the 2015 earnings guidance range comparing non-GAAP earnings from continuing operations for the first nine months of 2015 versus 2014, earnings are up 8% year-over-year. Drivers of the differences between the statutory tax rates for IPL, WP&L and AEC and the actual forecasting effect the tax rates for 2015 and 2014 is profiled on slide 9. Now let’s review our 2016 guidance. Last evening we issued our consolidated 2016 guidance range of $3.60 to $3.90 earnings per share. A walk on the mid points of 2015 to 2016 estimated guidance range is shown on slide 10. The key drivers for the 5% growth in earnings relate to infrastructure investments including higher AFUDC related to the construction of the Marshalltown generating station. The 2016 guidance range assumes normal weather and modest retail sales increases of approximately 1% for IPL and WP&L when compared to 2015. Also the earnings guidance is based upon the impact of IPLs and WP&Ls previously announced retail electric base rate settlements. The IPL settlement reflected rate based growth primarily from placing the Lansing scrubber in service in 2015 and the Ottumwa baghouse scrubber and performance improvement in service in 2014. The increase in revenue requirements related to rate base editions is offset by the elimination of DAEC purchase power capacity payments. In 2016 IPL expects to credit customer bills by approximately $10 million. By comparison the billing credits in 2015 are expected to be approximately $25 million. During 2016 IPL expects to provide tax benefit billing credits to electric and gas customers with approximately $62 million when compared to $72 million in 2015. As in prior years the tax benefit riders have a quarterly timing impact, but are not anticipated to impact full year 2015 and 2016 results. The WP&L settlement reflected electric rate base growth for the Edgewater unit 5 baghouse projected to be placed in service in 2016. The increase in revenue requirements in 2016 for these and other rate base additions were completely offset by lower energy efficiency cost recovery amortizations. Also included in WP&L’s rate settlement was an increase in transmission costs primarily related to the anticipated allocation of SSR costs. As a result of a third quarter issued after the settlement the amount of the transmission cost billed to WP&L in 2016 will be lower than what was reflected in the settlement. Since the PSCW approved escrow accounting treatment for the transmission cost. The difference between the actual cost billed to WP&L and those reflected in settlement will accumulate in a regulatory liability. We estimate that this regulatory liability will have a balance of approximately $35 million by the end of 2016. We view this regulatory liability as another mechanism we can use to minimize future rate increases for Wisconsin retail electric customers. Retirement plan expense is currently expected to be approximately $0.03 per share higher in 2016 largely due to lower than expected asset returns forecasted for 2015. These amounts will be updated at year end 2015 when determining the actual 2016 plan expense. Given the changes expected in income tax expense in 2016 slide 11 has been provided to assist you in modeling the forecasted 2016 effective tax rates for IPL, WP&L and AEC. Turning to our financing plans cash flows from operation are expected to be strong given the earnings generated by the business. We also will benefit given we do not expect to make any material federal income tax payments in 2016. These strong cash flows will be partially reduced by credits to customer bills in accordance with IPL’s tax benefit riders and IPL’s customer billing credit resulting from the settlement. We believe that with our strong cash flows and financing plans we will maintain our target liquidity and capitalization ratios as well as high quality credit ratings. Our 2016 financing plan assumes will be issuing approximately $25 million of new common equity through our shareowner direct plan. The 2016 financing plan also anticipates issuing long-term debt including up to $300 million at IPL and up to $310 million at the [parent] and Alliant Energy Resources. The $310 million of proceeds at the parent and Alliant Energy Resources are expected to be used to refinance maturity of term loans. We may adjust our plans as deemed prudent if market conditions warrant and as our debt and equity needs continue to be reassessed. As we look beyond 2016 our equity needs will be driven by the proposed riverside expansion project. Our forecast assumes that the capital expenditures for the riverside expansion in 2017 and 2018 will be financed primary by a combination of debt and equity. Our current financing forecast assumes no extension of bonus depreciation deduction. Under this assumption Alliant energy will be making modest federal tax payments starting in 2017 it will continue to use net operating losses for the next two years as offset to federal taxable income. We have several current and planned regulatory dockets of notes for the rest of 2015, 2016 and 2017 which we have summarized on 512. Later this year we anticipate a decision from PSCW on the 2016 fuel monitoring level. Next year we anticipate a decision on the Wisconsin riverside expansion proposal and on the Iowa natural gas pipeline. Also in 2016, we plan to file a emissions planned budget in Iowa and the Wisconsin retail electric and gas base case per rates in years 2017 and 2018. The next Iowa retail electric and gas base rate cases are expected to be filed in the second quarter of 2017. We very much appreciate your continued support of our company and look forward to meeting with you at EEI. The slides to be discussed at EEI are posted on our website as we do with all of our investor relations conference slides. At this time I will turn the call back over to the operator to facilitate the question-and-answer session. Question-and-Answer Session Operator Thank you, Mr. Hanson. [Operator Instructions] And we will take our first question from Andrew Weisel with Macquarie Capital. Andrew Weisel Good morning guys. First question is on the [four set] charged for voluntary employee separation. What does that impact on? How is that going to impact OEMs going forward? Tom Hanson That will be a reduction to ONM on going forward and that’s reflected in our forecast in terms of 2016 guidance. Andrew Weisel And what is the forecast for ONM next year? Tom Hanson We are assuming that it will be about a 2% increase now recognizing that this excludes the normal energy efficiency cost as well as any of the regulatory amortization that flow through ONM as well. Andrew Weisel Got it. Next a couple of questions on riverside, first in terms of the CapEx you laid out. I see that you lowered it for next year spending by that 95 million can you give little more detail on that. Is that assuming a little bit of a delay when the construction begins? Pat Kampling No not at all. Now that we are getting bids from the contractors, this is the timing of the bids, the cash flow that they are laying out while we changed the not only did we change the total number but we changed the timing of the payments. Andrew Weisel Okay. The total number if I heard you correctly was only down about 20 million is that right? Pat Kampling No, it’s down, if it goes from mid-point to mid-point it’s down 50 million, 50. Andrew Weisel Okay. Then next question I have is with the potential for PTA instead of riverside, if riverside were to be either delayed or canceled could you talk about how you might be able to back fill some of that spending in terms of what might go in and how soon you will be able to show those results? Pat Kampling Yes, Andrew it’s a little preliminary first to give a backup for capital for riverside right now. It would be honest to tell you though for 2016 it would be tough to fill the capital that we have laid out in 2016, but we’ll discuss as we get further down the year in 2016 what the back fill could possibly be. Andrew Weisel Okay. Thank you very much. I’ll let other people ask questions. Operator And we will take our next question from Brian Russo with Ladenburg Development. Brian Russo Good morning. Pat Kampling Good morning Brian. Brian Russo Just in terms of the 2016 guidance what kind of earned ROE are you seeing at IPL and WP&L maybe at the mid-point? Tom Hanson We are assuming that we would earn our authorized returns in both jurisdiction. Brian Russo Okay. So what gets you to the high end of the range? Pat Kampling The high end sales are higher than we expect. We currently expect 1% increase in sales but if they come in higher it would definitely bring us to the high end of the range. Brian Russo Okay and then as you we looked into 2017 Marshalltown will be added base rates and I believe correct me if I am wrong but that’s the allowed ROEs of 11.4%. So I would imagine that your earned ROE in 2017 will be enhanced relative to the earned ROE assumption in 2016. Is that the way to look at it? Pat Kampling Brian so the allowed ROE for Marshalltown is 11%, 11.0. Brian Russo Okay. Pat Kampling But as we go through internal and final rates you will see our earned returns increase at Iowa. Brian Russo Okay great. Thank you very much. Operator And Ms. Gill there are no further questions at this time. Susan Gille With no more questions this concludes our call. A replay will be available through November 13, 2015 at 888-203-1112 for U.S. and Canada, or 719-457-0820 for international. Callers should reference conference ID 8244179. In addition, an archive of the conference call and a script of the prepared remarks made on the call will be available on the Investors section of the company’s website later today. We thank you for your continued support of Alliant Energy. And feel free to contact me with any follow-up question. Operator And ladies and gentlemen that does conclude today’s conference. Thank you for your participation. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. 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What’s In Your Wallet: The Case For Cash

Strong returns to risk assets have largely precluded the consideration of cash in a portfolio. In times of uncertainty and low expected returns, however, holding cash entails little opportunity cost. Further, holding cash provides a valuable option to take advantage of opportunities as they arise in the future. Following a period of high inflation in the 1970s and early 1980s, and then a period of 33 years of declining interest rates that boosted asset returns, it’s no wonder that cash has fallen out of the lexicon of useful investment options. In addition to this experience, some of the core tenets of investment theory have also helped to relegate cash to an afterthought as an investment option. Regardless, the lesson taken by many investors has been to remain fully invested and let risk assets to do what they do – appreciate over time. Not surprisingly, this has largely obviated the utility of cash. We don’t live in a static world though, and sometimes things change in ways that challenge underlying assumptions and change the endeavor in a fundamental way. In times of ever-increasing asset appreciation, investors just need exposure and cash serves as a drag. In leaner times characterized by lower expected returns, however, the opportunity cost of cash is far lower. More importantly, it also provides a valuable option to take advantage of future opportunities as they arise. Several factors have contributed to the lowly status of cash. An important one has been a core tenet of investment theory that indicates higher returns accrue from assets with higher levels of risk. Money managers and asset allocators such as investment consultants and wealth managers have run with this partly out of desire to help clients earn better returns, but also to out of desire to increase their own asset management fees. Many of these fiduciaries, however, take a shortcut by basing allocation decisions on past records rather than by making determinations of future expectations. This practice has two important consequences for investors. One is that it almost permanently consigns cash allocations to only the most extremely risk averse investors. Another is that it structurally avoids addressing situations in which risk asset opportunities deviate materially from their historical average. And deviate they do from time to time. Stocks, for example, hit exceptionally high valuations in 2000 and 2007. Identifying such instances is not a matter of using Ouija boards and engaging in occult activities either; straightforward analytical techniques are widely available (see John Hussman’s work [ here ] for an excellent analysis). These instances create significant opportunities to avoid low expected future returns by temporarily holding cash instead. To skeptics leery of making any changes, such a dynamic response falls far short of market timing. It merely involves adapting one’s exposure to be consistent with longer term risk/reward characteristics as they go through cycles over time. This really just involves a common sense approach of only taking what is given and not overreaching, but it is also completely consistent with the Kelly criterion prescription for wealth maximization that we discussed [ here ]. The problem is that at the current time, it’s not just stocks that look expensive. With rates near zero, and below zero in many countries, fixed income also looks unattractive. As James Montier of GMO complained [ here ], “Central bank policies have distorted markets to such a degree that investors are devoid of any buy-and-hold asset classes.” And that was in 2013 when the S&P 500 was 400 points lower! He followed up by expanding on his position [ here ], “When we look at the world today, what we see is a hideous opportunity set. And that’s a reflection of the central bank policies around the world. They drive the returns on all assets down to zero, pushing everybody out on the risk curve. So today, nothing is cheap anymore in absolute terms.” In other words, we seem to be experiencing a rare global phenomenon in which virtually all assets are overpriced. For a generation (and more) that grew up on strong asset returns, this may seem surreal and hard to believe. Some things move in bigger cycles than our personal experience, though, and the history of asset returns certainly bears this out. On this score, Daniel Kahneman highlighted in his book, Thinking, Fast and Slow , exactly the types of situations in which we should not trust experience. In his chapter “Expert intuition: When can we trust it?”, he notes that a necessary condition for acquiring a skill is, “an environment that is sufficiently regular to be predictable.” Given our current environment of unprecedented levels of debt on a global basis and central banks intentionally trying to increase asset prices by lowering interest rates, in many cases below zero, it is doubtful that anyone can claim that this environment is “sufficiently regular to be predictable.” Indeed, this environment more closely resembles a more extreme condition identified by Kahneman: “Some environments are worse than irregular. Robin Hogarth described ‘wicked’ environments, in which professionals are likely to learn the wrong lessons from experience.” For those who are anchored to the notion that risk assets are utilities that reliably generate attractive returns, and for investors who are making decisions based on the last thirty years of performance, Kahneman’s work raises a warning flag: This is likely to be a situation in which your natural, intuitive, “system 1” way of thinking may lead you astray. This is a good time to engage the more thoughtful and analytical “system 2” to figure things out. If indeed we must contend with a “hideous opportunity set”, what options do investors have? The answer many receive from their investment consultants and wealth managers is to diversify. The practice of diversification works on the principle that there are a lot of distinct asset classes which implicitly suggests that there is almost always an attractive asset somewhere to overweight. This response creates two challenges for investors. One, as mentioned in the last Areté Blog post [ here ], is that, “The utility of diversification, the tool by which most investors try to manage risk, has been vastly diminished over the last eight years.” This is corroborated by Montier who notes, “Investors shouldn’t overrate the diversifying value of bonds … When measured over a time horizon of longer than seven years, Treasury bonds have actually been positively correlated to equities.” A second issue is that diversification does not really address the problem. As Ben Hunt notes [ here ], “investors are asking for de-risking, similar in some respects to diversification but different in crucial ways.” As he describes, “There’s a massive disconnect between advisors and investors today, and it’s reflected in … a general fatigue with the advisor-investor conversation.” The source of the disconnect is that “Advisors continue to preach the faith of diversification,” which is just a rote response to concerns about risk, while “Investors continue to express their nervousness with the market and dissatisfaction with their portfolio performance.” In short, “Investors aren’t asking for diversification;” they are asking for de-risking. And one of the best answers for de-risking is cash. In an environment of low expected returns wrought by aggressive monetary policy, James Montier makes a powerful case for cash [ here ]. He describes, “If the opportunity set remains as it currently appears and our forecasts are correct (and I’m using the mean-reversion based fixed income forecast), then a standard 60% equity/40% fixed income strategy is likely to generate somewhere around a paltry 70 bps real p.a. over the next 7 years!” In other words, we are stuck in an investment “purgatory” of extremely low expected returns. He suggests some ideas for exceeding the baseline expectation of paltry returns, but his favorite approach is to “be patient”, i.e., to retain cash and wait for better opportunities. As he duly notes though, “Given the massive uncertainty surrounding the duration of financial repression, it is always worth considering what happens if you are wrong,” and purgatory is not the only possibility. Montier’s colleague, Ben Inker, followed up with exactly this possibility [ here ]: “He [Montier] called it Purgatory on the grounds that we assume it is a temporary state and higher returns will be available at some point in the future. But as we look out the windshield ahead of us today, it is becoming clearer that Purgatory is only one of the roads ahead of us. The other one offers less short-term pain, but no prospect of meaningful improvement as far as the eye can see.” Inker’s recommendation is, “if we are in Hell (defined as permanently low returns), the traditional 65% stock/35% bond portfolio actually makes a good deal of sense today, although that portfolio should be expected to make several percentage points less than we have all been conditioned to expect. If we are in Purgatory, neither stocks nor bonds are attractive enough to justify those weights, and depending on the breadth of your opportunity set, now is a time to look for some more targeted and/or obscure ways to get paid for taking risk or, failing that, to reduce allocations to both stocks and bonds and raise cash.” Once again, cash figures prominently as an option. An unfortunate consequence of these two possible paths is that the appropriate portfolio constructions for each are almost completely mutually exclusive of one another. If you believe we are in investment purgatory and that low returns are temporary, you wait it out in cash until better returns are available. If you believe we are in investment hell and that low returns are the new and permanent way of life, something like the traditional 65% stock/35% bond portfolio “still makes a good deal of sense.” The catch is that the future path is unknowable and this uncertainty has implications as well. In regards to this uncertainty Montier’s observation is apt: “One of the most useful things I’ve learnt over the years is to remember that if you don’t know what is going to happen, don’t structure your portfolio as though you do!” That being the case, most investors should prepare for at least some chance that either path could become a reality. And that means having at least some exposure to cash. In conclusion, managing an investment portfolio is difficult in the best of times, but is far harder in times of uncertainty and change. When valuations are high, uncertainty is high, and diversification offers little protection, there are few good options and it makes sense to focus more on defense than on offense. In times like this, there are few better places to seek refuge than in cash. The degree to which one should move to cash depends heavily on one’s particular situation and investment needs. If you are a sovereign wealth fund or a large endowment with low draws for operating costs, your time horizon is essentially infinite so it may well make sense to stay pretty much fully invested. In most other situations, it probably makes sense to have some cash. If your spending horizon is shorter than the average 50 year duration of equities, if you may have liquidity needs that exceed your current cash level, or if you are trying to maximize your accumulation of wealth (and minimize drawdowns), cash can be a useful asset. Finally, the current investment environment has highlighted a growing divide between many investors and their advisers. Investors who are well aware of the risks pervading the market are seeking to manage the situation but all too often receive only rote directives to “diversify” in response. They may even be chided for shying away from risk as if risk is an inherently good thing. Such investors should take comfort in the knowledge that it only makes sense to take on risk insofar as you get well compensated for doing so. Further, identifying assets as expensive is in many ways a fundamentally optimist view – it implies that they will become cheap again someday and will provide much better opportunities to those who can wait. (click to enlarge)

Empire District Electric’s (EDE) CEO Brad Beecher on Q3 2015 Results – Earnings Call Transcript

Empire District Electric Co (NYSE: EDE ) Q3 2015 Earnings Conference Call October 30, 2015 13:00 ET Executives Dale Harrington – IR Brad Beecher – President & CEO Laurie Delano – VP, Finance & CFO Analysts Brian Russo – Ladenburg Thalmann Paul Ridzon – KeyBanc Capital Markets Julien Dumoulin-Smith – UBS Operator Welcome to the Empire District Electric Third Quarter 2015 Earnings Conference Call. [Operator Instructions]. Please note, this event is being recorded. I would now like to turn the conference over to Dale Harrington. Please, go ahead. Dale Harrington Thank you, Laura. Good afternoon, everyone. Welcome to the Empire District Electric Company’s third quarter 2015 earnings conference call. Our press release announcing third quarter 2015 results was issued yesterday afternoon. The press release and a live webcast of this call, including our accompanying slide presentation are available on our website at www.empireDistrict.com. A replay of the call will be available on our website through January 31, 2016. Joining me today are, Brad Beecher, President and Chief Executive Officer; and Laurie Delano, Vice President, Finance and Chief Financial Officer. In a few moments, Brad and Laurie will be providing an overview of our 2015 third quarter year-to-date and 12-month ended September 30, 2015 results, as well as highlights on other key matters. But before we begin, let me remind you that our discussion today includes forward-looking statements and the use of non-GAAP financial measures. Slide 2 of our accompanying slide deck and the disclosure in our SEC filings present a list of some of the risks and other factors that could cause future results to differ materially from our expectations. I’ll caution that these lists are not exhaustive and the statements made in our discussion today are subject to risks and uncertainties that are difficult to predict. Our SEC filings are available upon request or may be obtained from our website or from the SEC. I would also direct you to our earnings press release for further information on why we believe the presentation of estimated earnings per share impact of individual items and a presentation of gross margin, each of which are non-GAAP presentations, is beneficial for investors in understanding our financial results. With that, I will now turn the call over to our CEO, Brad Beecher. Brad Beecher Thank you, Dale. Good afternoon, everyone. Thank you for joining us. Today, we will discuss our financial results for the third quarter year-to-date and 12-months ended September 30, 2015 periods. We will also provide an update on other recent Company activities. Yesterday, we reported consolidated third quarter 2015 earnings of $25.3 million or $0.58 per share. This compares to the same period in 2014, when earnings were $23.9 million or $0.55 per share. Year-to-date earnings through September 30 are $46.7 million or $1.07 per share, compared to $56 million, or $1.29 per share in the 2014 year-to-date period. For the 12-month period ending September 30, 2015, earnings were $57.8 million or $1.33 per share – $1.32 per share on a diluted basis compared to September 30, 2014 12-month earnings of $71.2 million or $1.65 per share. Laurie will provide more details on our financial results in her discussion. During their meeting yesterday, the Board of Directors declared a quarterly dividend of $0.26 per share payable December 15, 2015 for shareholders of record as of December 1. This represents a 4.4% annual yield at yesterday’s closing price of $23.41 per share. On slide 3 of our presentation, we provided a summary of results for the quarter, year-to-date and 12-month ended periods, as well as highlights during the quarter. We’ll discuss these more throughout the call. On July 26, we put Missouri customer rates into effect to begin recovery of our investment in our Asbury Air Quality Control System project. These rates will add around $17.1 million to our annual base revenues, reflecting a lowering of our fuel base by $1.60 per megawatt hour. With these rates now in place and as we announced in our earnings release yesterday, our full-year weather-normal earnings guidance range of $1.30 to $1.45 per share we provided in February of this year remains unchanged. On our last call, we reported plans for our Missouri rate filing during the fourth quarter of this year. As indicated, we made a filing with the Missouri Public Service Commission on October 16, 2015 requesting an increase in annual electric revenues of approximately $33.4 million or 7.3%. The most significant driver in the case is cost recovery for the Riverton unit 12 combined cycle project. As shown on slide 4, at the end of the quarter, construction at Riverton is 93% complete. Project costs were approximately $150 million excluding AFUDC. The tie-in of new and existing equipment is underway. Preparation for testing and commissioning activities will begin later this year, with scheduled completion in early to mid-2016. The combined cycle project will replace the capacity of retiring coal fire generators at Riverton and ensure our compliance with the Mercury air toxic standards and the cross-state air pollution rule. The Riverton project has an estimated total cost of $165 million to $175 million. Other factors in the filing include, increased transmission expense, administrative and maintenance expense and costs incurred as a result of a mandated solar rebate program. The case also reflects cost savings for customers resulting from revised depreciation rates and lower average interest costs. The filings seeks continuation of the fuel adjustment clause which provides for semi-annual adjustments to customers’ bills, based on the varying costs of fuel and purchase power. We expect new rates to take effect for Missouri customers by September 2016. Keep in mind, as we have previously – discussed previously, with an expected in-service date for Riverton in early to mid-2016 and continued similar customer energy sales, we expect 2016 results to be impacted by some depreciation and property tax lag. Laurie will talk more about the new Missouri reg case in a few moments. On October 26, we filed a request with the Oklahoma Corporation Commission for rate reciprocity using the Missouri proposed tariffs. An administrative rule, providing rate reciprocity to any electric Company who serves less than 10% of its total customers within the state of Oklahoma, took effect in August of this year. As a result, future commission approved increases in Missouri rates will be effective for Empire’s Oklahoma customers, subject to approval of the Oklahoma Corporation Commission. I will now turn the call over to Laurie for a discussion of our financial details. Laurie Delano Thank you, Brad. Good afternoon, everybody. As we review our third quarter 2015 earnings per share results of $0.58 compared to our 2014 results of $0.55, I’ll continue to refer to our webcast presentation slides to talk about various impacts to the quarter. As usual, the slides provide a consolidated non-GAAP estimated basic earnings per share reconciliation for the quarter, year-to-date and 12-month ended periods. Again, this information supplements the earnings per share reconciliation and other information we provided in our press release yesterday. As always, the earnings per share numbers throughout the call are provided on an after tax estimated basis. As Brad mentioned, third quarter results were slightly higher compared to the 2014 quarter and pretty much on target with our 2015 earnings guidance. The new customer rates that became effective July 26 reflecting the costs of our Asbury project added positively to the quarter. However, as we spoke about on our last call, we experienced about a month of regulatory lag on Asbury depreciation, property tax and Riverton 12 maintenance contract costs during the quarter due to the timing of the new rates. When comparing to the 2014 periods, our year-to-date and 12-month ended results continued to be negatively impacted by the depreciation, property tax and maintenance contract lag and the very cold weather during the 2014 heating season. Slide 5 provides a roll-forward of the 2014 third quarter earnings per share of $0.55 to the 2015 quarter results of $0.58 per share. The margin callout box on Slide 5 provides a breakdown of our estimates of the various components that resulted in an increase in electric gross margin of approximately $8.7 million or about $0.13 per share. The implementation of our new Missouri retail customer rates in July drove an increase in margin of about $0.06 per share compared to the 2014 quarter. Again, just as a reminder, our $17.1 million increase in annual base revenues is net of a base fuel decrease of $1.60 per megawatt hour, so the resulting change in margin was negligible. Weather and other volumetric factors drove an estimated increase in margin of about $0.04 per share. On system kilowatt hour sales were up across all of our customer classes during the quarter, increasing in aggregate about 3.3% compared to the 2014 quarter. Warmer weather drove an increase of just over 10% in total cooling degree days compared to the same quarter last year. You may recall that July 2014 was among the coolest Julys in the past 30 years. Cooling degree days were also about 5.3% higher than the 30-year average. Our total sales volume for the quarter was pretty much on target with our guidance. Increased customer counts added about $0.01 per share to margin. Other items including the timing of our fuel deferrals combined to add another estimated $0.02 per share to margin when compared to the third quarter in 2014. Our gas segment retail sales declined slightly quarter over quarter. However, gas segment margin was relatively unchanged. As you can see, on the O&M callout box on slide 5, our overall O&M costs were relatively flat quarter over year. An increase in depreciation and amortization expense of approximately $1.5 million, reflective of the higher levels of planned in-service primarily due to our Asbury project, reduced earnings per share about $0.02. Higher levels of plant in-service and an increase in our effective tax rate also drove an increase in property and other taxes, reducing earnings per share about $0.04. Increases in interest charges and changes in other income and deductions combined with reduced allowance for funds used during construction or AFUDC, decreased earnings in aggregate another $0.04 per share. Our year-to-date earnings are $1.07 per share on net income of $46.7 million. This is a decrease of $0.22 per share over the same period last year, when we earned $1.29 per share. However, again, as Brad mentioned, our year-to-date results are on target with our 2015 earnings guidance. As shown on slide 6, increased customer rates and customer growth were positive drivers of the $0.07 increase in margin. The timing of our fuel deferrals and other fuel recovery components were also positive drivers. However, these positive items were offset by the impacts of weather and other volumetric factors, a January 2015 FERC refund to our four wholesale customers which we have discussed on previous calls and reduced margin from our gas segment. Increased production maintenance expense was the primary driver of an increase in overall O&M expenses that lowered earnings per share approximately $0.07 during the period. This increase is reflective of our Riverton 12 maintenance contract which was effective January 1 and the planned major maintenance outage for our steam turbine at our State Line combined cycle facility. We discussed both of these items on last quarter’s call. Again, we’re seeing increased depreciation and amortization expenses reduce earnings approximately $0.08 per share. Increases in property and other tax expenses, interest charges and changes in other income and deductions combined with a reduced level of AFUDC, again drove earnings down about $0.13 per share. Turning to our 12-month ended results, our net income decreased $13.4 million or $0.32 per share on an undiluted basis when compared to the 2014 12-month ended period. Slide 7 provides a breakdown of the various components that result in this period-over-period decrease in earnings. As you can see on the callout box on slide 7, increased customer rates, customer growth and the timing of our fuel deferrals and other fuel recovery components contributed positively to margin. However, these positive impacts were largely offset by weather and other volumetric impacts, the FERC wholesale refund and reduced gas segment margin. These changes netted together increased margin an estimated $0.04 per share year-over-year. The callout box on slide 7 provides a breakdown of consolidated operating and maintenance expenses that drove a $9.3 million or $0.13 year-over-year decrease in earnings per share. As we saw in the year-to-date period, increased production maintenance expense was a significant driver of the increase in overall O&M expenses. Again, as a result of our Asbury project, we’re seeing increased electric depreciation and amortization expense reducing earnings per share around $0.09. Increases in property and other tax expenses reduced earnings another $0.05 per share. Again, increased interest charges, changes in other income and deductions, the dilutive effect of common stock issuances and reduced AFUDC levels, drove earnings about $0.09 per share lower. On slide 8, we’re again illustrating the major drivers of our earnings through 2015 and into 2016. As we have previously disclosed, our guidance range assumed an August 1, 2015 effective date for the new Missouri customer rates. We’ve talked about the depreciation and maintenance expense lag effects on previous calls and today. With the July 26 effective date of our new customer rates, that impact will lessen throughout the remainder of the year. We will, however, continue to see increased maintenance expense as a result of our Riverton maintenance contract. As Brad mentioned, we expect the rates for our newly filed Missouri rate case to be effective in September of 2016. Turning to our balance sheet for just a moment. At September 30, I’m pleased to report our retained earnings balance was $102.9 million. This marks a milestone and that is the first time in Empire’s history, we have reported a retained earnings balance of over $100 million. As I alluded to on our last call on August 20, we received the proceeds from a $60 million delayed settlement offering of privately placed first mortgage bonds. These are 3.59% series bonds and they are due in 2030. We will use the proceeds to refinance some short-term debt and for general corporate purposes. Subsequently at the end of the quarter, we had $16.3 million of short-term debt outstanding out of our $200 million in capacity. Looking forward, we have $25 million of first mortgage bonds that mature in late 2016. At this time, we’re not planning to refinance this debt when it matures. On slide 9, we have updated our trailing 12-month return on equity charge. At the end of the third quarter, our ROE was approximately 7.2%, similar to our second quarter results. Slide 10 represents an updated capital expenditures and net plant projection plan for the next five years. As you can see on the slide, our five-year capital expenditures projections, excluding AFUDC, but including retirement projects and expenditures are as follows, in 2016, $124.1 million; in 2017, $117.4 million; in 2018, $167.7 million; 2019, $160.9 million; and in 2020, $119.8 million. This capital expenditures plan does not contain any major changes from the plan we presented at this time last year. The 2016 and 2017 projected expenditures return to more of a maintenance level of capital spending, providing a break for our customers from the rate increases resulting from our Asbury and Riverton projects. It also provides an opportunity for us to catch up some of the regulatory lag that we experienced during that time. Capital expenditures ramp up again in 2018 and 2019, as we focus our spending on customer reliability, communications and efficiency initiatives. As you can see from the slide, with this capital expenditures plan, we continue to project rate base growth at about a 4% compounded interest rate over the next five years. We’re using our net plant levels, net of deferred taxes to approximate our rate base levels. In addition, we have not assumed any bonus depreciation beyond 2014, nor have we assumed any expenditures related to the clean power plant in our projections. As we have seen historically, this net plant increase realized from building rate base infrastructure will drive our earnings growth. Turning to our recent regulatory activities, slide 11, summarizes the key aspects of our just-filed Missouri rate case and provides you with the docket number under which our testimony is filed. As Brad stated, we’re seeking a $33.4 million increase in base revenues which is about a 7.3% increase. The test year, we have filed ends June 30, 2015. We have requested an expense true-up through March 31, 2016, assuming an in-service date of June 1 for the Riverton 12 project. Our requested return on equity in this case is 9.9%. Using a consolidated capital structure of approximately 51% to 49% debt equity, we applied a 7.58% rate of return to our filed Missouri jurisdictional rate base of $1.368 billion to arrive at our operating income requirement. Our solar program compliance costs are also included in this Missouri rate filing. Last quarter, we reported on the launch of a mandated solar rebate program for customers. As of September 30, we had received about 250 rebate applications, totaling around $3.4 million in rebate-related costs. This represents approximately 3,300-kilowatts of solar capacity. These costs have been deferred onto our balance sheet. Similar to our previous rate case to recover our Asbury expenditures, we will experience a period of lag between the in-service date of the Riverton conversion and the time when the new customer rates are put in place. Assuming the Missouri Public Service Commission’s 11-month procedural schedule, new rates would become effective in mid-September 2016. Finally, on slide 12, we have a summary of our other regulatory and legislative filings, we have made since the first of the year, including our October 26 filing with the Oklahoma Corporation Commission for the reciprocal rate approval of the customer rates in our new Missouri filing which Brad talked about. I’ll now turn the discussion back over to Brad. Brad Beecher Thank you, Laurie. We continue to execute on our environmental compliance plan. As I mentioned earlier, the Riverton combined cycle unit is on track for completion in early to mid-2016. Once operational, the high efficiency of the unit will help us hold down fuel costs while lowering emissions and protecting the environment. In August, the EPA released its final rules for the clean power plan. The overall objective of the plan is to reduce nationwide carbon dioxide emissions by 32%, below 2005 levels by 2030. The next step is for individual states to develop compliance plans or partner with neighboring states on collaborative plans which are due to the EPA in September of 2016. A two-year extension for submitting final plans is available. We’re actively working with state environmental agencies to encourage the development of a regional plan. We have attended multiple meetings and workshops in Missouri, Kansas and Arkansas and are engaged on a national level through our membership in the Edison Electric Institute. We will continue our focus on the development of a least cost compliance option for our region, while also ensuring our ability to effectively utilize existing generation resources located across the multiple states we serve. In our southeast Kansas area earlier this month, local officials joined us in the dedication of a new electrical substation. The $4 million project is part of our ongoing initiative to strengthen the energy delivery system and enhance reliable service for our customers. This is one of several reliability upgrades being completed across our service area. Plans for the development of a new medical school in Joplin are still on track. Earlier this year, Kansas City University of Medicine and Biosciences announced plans to develop a medical school in Joplin, using the 150,000 square-foot building previously used by Mercy Hospital. Use of the existing structure will allow the medical school to open in the fall of 2017 with an estimated 600 students when the college is full. Most important to our business, the medical school is estimated to have an annual regional economic impact of over $100 million per year once it reaches full maturity. With that, I will now turn the call back to the operator for your questions. Question-and-Answer Session Operator [Operator Instructions]. And our first question will come from Brian Russo of Ladenburg Thalmann. Brian Russo Just curious, the September 2016 for new rates effective in Missouri, that assumes it goes the whole 11 months and isn’t settled? Laurie Delano That’s correct, yes. That would be the 11-month jurisdictional time period in Missouri. Brian Russo Okay. What was the timeframe from when you filed the last case? From when new rates went into effect? Laurie Delano This last case, it was just right at about 11 months. Brian Russo Okay. Got it. Laurie Delano In the past, we have sometimes settled earlier. But not always. Brian Russo Okay. I think in the case you just filed, you think you mentioned a 49% equity ratio. Laurie Delano Yes. Brian Russo Okay. What’s the equity ratio embedded in rates currently? Laurie Delano I believe it’s a little bit higher than that, around 50%, but not very much different from that. Brian Russo Okay. Then when I look at slide 9 – this might be a difficult question to answer. But is there – can you point to one or two years where your CapEx is more normalized, meaning you don’t have any major projects hitting the income statement and creating lag? Just to get a sense of kind of what’s kind of the structural lag you just have with the historical test year? Brad Beecher Brian, I don’t know that there are any years within this period we’ve got in front of you where we didn’t have something major going on. In 2008, 2009, 2010, obviously we had all the expenses piling up for IO-102 and Plum Point. 2011, we had the tornado. Then 2012 was relatively small, but then we start ramping into Asbury AQCS pretty shortly thereafter. Brian Russo Just, is there any way to weather normalize 3Q 2014 sales or load – because obviously, you had a year-over-year favorable variance due to weather. Just want to get a sense of the – what kind of normalized load growth this is looking like? Brad Beecher For this quarter that we just completed for third quarter 2015, I would say that overall, our total sales were pretty much what we expected from a weather normal standpoint. We had a little bit higher commercial and less than – and less than what we expected residential which kind of evened out. But, in the past we’ve talked about the fact that we think our annual weather normal sales or about 5 million-megawatt hours. We’re not seeing any major change to that. Brian Russo Okay. And did you see – did you experience any impact from the new hospital and several new schools that became fully operational in the third quarter? Laurie Delano We’re seeing that. I think our press release kind of lays some of those numbers out. We’re seeing an uptick in our commercial sales and that’s a lot of what’s driving that, particularly the hospital. Again, our residential sales are a little bit below what we expected. I think we’re seeing some of that energy efficiency come into that. Operator And the next question is from Paul Ridzon of KeyBanc. Paul Ridzon Your $150 million into Riverton 12, is that what you said? Brad Beecher Yes. Paul Ridzon At this point, do you have any clarity on kind of which end of that $165 million to $175 million range you might end up in? Brad Beecher We’re still finishing up the project and there’s quite a lot of things can happen. We’ve not changed that range as we have, as we talked to the market or to the Public Service Commission. Operator And the next question comes from Julien Dumoulin-Smith of UBS. Julien Dumoulin-Smith Following up a little bit on that a lag question, can we just get a little bit more articulate about your expectations on this rate case relative to the last and the year-over-year comps is you kind of think through the next case? Is there – I suppose maybe the first question out of the gates is, is there any reason to think that lag would shift structurally in this case versus the last for any discreet reason? Brad Beecher There is no change in law, so as soon as Riverton 12 goes into service, we’ll start depreciating it. We will experience that lag until we get new rates on both depreciation and property tax. Laurie Delano One thing to keep in mind. I think maybe it’s on the slide, the Riverton depreciation rate will be a little bit lower than that Asbury rate was, more in the 2% range, whereas Asbury was in a 5% range, just because we’ve got a longer life on this Riverton project. So that will be one of the differences. But the depreciation will still start when it goes into service. Julien Dumoulin-Smith Right. So realistically speaking, you’ve got a few months, call it 1Q 2016 you’re not taking the depreciation impact. You get the year-over-year rate case benefit, you go in for the 2Q and 3Q, in which you’re booking depreciation against the asset. In theory, that should be the worst of the lag phenomenon. Then by 4Q, you should have the new rates in effect which are offsetting the D&A? Is that broadly a good way to think about it? Laurie Delano That would be correct. Julien Dumoulin-Smith Excellent. Then just what is your latest, given the sales growth trends that you just described in terms of quote-unquote, normalized lag, if you will? Obviously, the first quarter coming out of a new rate case will be the top. But how good can it get? Laurie Delano The basis points in lag, is that what you’re – Julien Dumoulin-Smith Exactly. How small of a lag can you get? Laurie Delano Julien, absent a change in law, change in the way our customer energy usage is happening, I think our historical pattern of ups and downs that you see on slide 9 is a good indication of what we can achieve on both ends of the spectrum. Julien Dumoulin-Smith All right. Excellent. Any other comments about changes at the commission? I would just be curious if there’s anything afoot, policy-wise, et cetera. Brad Beecher Julien, I don’t know that there’s a whole lot of things new policy-wise. One thing that we’re looking forward to Kansas City was, had a requested some moneys for energy charging infrastructure for electric cars in their last case, that the commission declined to make a decision on. So I think that kind of policy decision may be coming in the future. We clearly keep watching ROE and ROE trends and those kinds of things at the commission. Operator [Operator Instructions] Showing no further questions, I would like to turn the conference back over to Brad Beecher for any closing remarks. Brad Beecher Thank you very much. Our management team remains dedicated to our long-term strategy as a high quality pure play regulated electric and gas utility, pursuing a low-risk rate base growth plan, managing a diverse environmentally compliant energy supply portfolio and maintaining constructive regulatory relationships in each of our jurisdictions. We’re committed to meeting today’s energy challenges with least cost resources, while ensuring reliable and responsible energy for our customers and an attractive return for our shareholders. We will be at the EEI Financial Conference November 8-10 in Florida. We look forward to seeing many of you there. As always, we appreciate you sharing your time with us today. Have a great weekend. Operator The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.